System and Method For Downhole Telemetry

ABSTRACT

A system and method are provided for providing electromagnetic (EM) measurement-while-drilling (MWD) telemetry capabilities using an existing mud-pulse MWD tool. An EM tool intercepts the output from the mud-pulse tool and generates an EM signal that mimics a mud-pulse pressure signal. The EM signal is intercepted at the surface by a receiver module that conditions the signal and inputs the signal into the existing pulse tool receiver. Since the EM signal mimics a mud-pulse signal, the pulse tool receiver does not require software or hardware modifications in order to process an EM telemetry mode. The EM tool can be adapted to also provide dual telemetry by incorporating a conventional pressure pulser that would normally be used with the pulse tool.

This application is a continuation-in-part of U.S. patent applicationSer. No. 11/538,277 filed on Oct. 3, 2006, which claims priority fromCanadian Patent Application No. 2,544,457 filed on Apr. 21, 2006, thecontents of both being incorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates generally to data acquisition during earthdrilling operations and telemetry systems therefor, and has particularutility in measurement while drilling (MWD) applications.

DESCRIPTION OF THE PRIOR ART

The recovery of subterranean materials such as oil and as typicallyrequires drilling wellbores a great distance beneath the earth's surfacetowards a repository of the material. The earthen material being drilledis often referred to as “formation”. In addition to drilling equipmentsituated at the surface, a drill string extends from the equipment tothe material formation at the terminal end of the wellbore and includesa drill bit for drilling the wellbore.

The drill bit is rotated and drilling is accomplished by either rotatingthe drill string, or by use of a downhole motor near the drill bit.Drilling fluid, often termed “mud”, is pumped down through the drillstring at high pressures and volumes (e.g. 3000 p.s.i. at flow rates ofup to 1400 gallons per minute) to emerge through nozzles or jets in thedrill bit. The mud then travels back up the hole via the annulus formedbetween the exterior of tie drill string and the wall of the wellbore.On the surface, the drilling mud may be cleaned and then re-circulated.The drilling mud services to cool and lubricate the drill bit, to carrycuttings from the base of the bore to the surface, and to balance thehydrostatic pressure in the formation.

A drill string is generally comprised of a number of drill rods that areconnected to each other in seriatim. A drill rod is often referred to asa “sub”, and an assembly of two or more drill rods may be referred to asa “Sub-assembly”.

It is generally desirable to obtain information relating to parametersand conditions downhole while drilling. Such information typicallyrelates to one or more characteristics of the earth formation that isbeing traversed by the wellbore such as data related to the size, depthand/or direction of the wellbore itself; and information related to thedrill bit such as temperature, speed and fluid pressure. The collectionof information relating to conditions downhole, commonly referred to as“logging”, can be performed using several different methods. Welllogging in the oil industry has been known for many years as a techniquefor providing information to the driller regarding the particular earthformation being drilled.

In one logging technique, a probe or “sonde” that houses formationsensors is lowered into the wellbore once drilling has progressed orcompleted. The probe is supported by and connected to the surface via anelectrical wireline, and is used to obtain data and send the data to thesurface. A paramount problem with obtaining downhole measurements via awireline is that the drilling assembly must be removed or “tripped” fromthe wellbore before the probe can be lowered into the wellbore to obtainthe measurements. Tripping a drill string is typically time consumingand thus costly, especially when a substantial portion of the wellborehas been drilled.

To avoid tripping the drill string, there has traditionally been anemphasis on the collection of data during the drilling process. Bycollecting and processing data during the drilling process. Without thenecessity of tripping the drill string, the driller can makemodifications or corrections to the drilling process as necessary. Suchmodifications and corrections are typically made in an attempt tooptimize the performance of the drilling operation while minimizingdowntime. Techniques for concurrently drilling the well and measuringdownhole conditions are often referred to as measurement-while-drilling(MWD). It should be understood that MWD will herein encompasslogging-while-drilling (LWD) and seismic-while-drilling (SWD)techniques, wherein LWD systems relate generally to measurements ofparameters of earth formation, and SWD systems relate generally tomeasurements of seismic related properties.

In MWD systems, sensors or transducers are typically located at thelower end of the drill string which, while drilling is in progress,continuously or intermittently monitor predetermined drilling parametersand formation data. Data representing such parameters may then betransmitted to a surface detector/receiver using some form of telemetry.Typically, the downhole sensors employed in MWD applications arepositioned in a cylindrical drill collar that is positioned as close tothe drill bit as possible.

There are a number of telemetry techniques that have been employed byMWD systems to transmit measurement data to the surface without the useof a wireline tool. One such technique involves transmitting data usingpressure waves in drilling fluids such as drilling mud. This telemetryscheme is often referred to as mud-pulse telemetry. Mud-pulse telemetryinvolves creating pressure signals in the drilling mud that is beingcirculated under pressure through the drill string during the drillingoperation. The information that is acquired by the downhole sensors istransmitted utilising a particular time division scheme to effectivelycreate a waveform of pressure pulses in the mud column. The informationmay then be received and decoded by a pressure transducer and analysedby a computer at a surface receiver.

In a mud-pulse system, the pressure in the drilling mud is typicallymodulated via operation of a valve and control mechanism, generallytermed a pulser or mud-pulser. The pulser is typically mounted in aspecially adapted drill collar positioned above the drill bit. Thegenerated pressure pulse travels up the mud column inside the drillstring at the velocity of sound in the mud, and thus the datatransmission rate is dependent on the type of drilling fluid used.Typically, the velocity may vary between approximately 3000 and 5000feet per second. The actual rate of data transmission, however, isrelatively slow due to factors such as pulse spreading, distortion,attenuation, modulation rate limitations, and other disruptive forcessuch as ambient noise in the transmission channel. A typical pulse rateis on the order of one pulse per second (i.e. 1 Hz).

An often preferred implementation of mud-pulse telemetry uses pulseposition modulation for transmitting data. In pulse position modulation,pulses have a fixed width and the interval between pulses isproportional to the data value transmitted. Mud-pressure pulses can begenerated by opening and closing a valve near the bottom of the drillstring so as to momentarily restrict the mud flow. In a number of knownMWD tools, a “negative” pressure pulse is created in the fluid bytemporarily opening a valve in the drill collar so that some of thedrilling fluid will bypass the bit, the open valve allowing directcommunication between the high pressure fluid inside the drill stringand the fluid at lower pressure returning to the surface via theexterior of the string. Alternatively, a “positive” pressure pulse canbe created by temporarily restricting the downward flow of drillingfluid by partially blocking the fluid path in the drill string.

Electromagnetic (EM) radiation has also been used to telemeter data fromdownhole locations to the surface (and vice-versa). In EM systems, acurrent may be induced on the drill string from a downhole transmitterand an electrical potential may be impressed across an insulated gap ina downhole portion of the drill string to generate a magnetic field thatwill propagate through the earth formation. The signal that propagatesthrough the formation is typically measured using a conductive stakethat is driven into the ground at some distance from the drillingequipment. The potential difference of the drill string signal and theformation signal may then be measured, as shown in U.S. Pat. No.4,160,970 published on Jul. 10, 1979.

Information is transmitted from the downhole location by modulating thecurrent or voltage signal and is detected at the surface with electricfield and/or magnetic field sensors. In an often preferredimplementation of EM telemetry, information is transmitted by phaseshifting a carrier sine wave among a number of discrete phase states.Although the drill string acts as part of the conductive path, systemlosses are almost always dominated by conduction losses within the earthwhich, as noted above, also carries the electromagnetic radiation. SuchEM systems work well in regions where the earth's conductivity betweenthe telemetry transmitter and the earth's surface is consistently low.However, EM systems may be affected by distortion or signal dampeningdue to geologic formations such as dry coal seams, anhydrite, and saltdomes.

Telemetry using acoustic transmitters in the drill string has also beencontemplated as a potential means to increase the speed and reliabilityof the data transmission from downhole to the surface. When actuated bya signal such as a voltage potential from a sensor, an acoustictransmitter mechanically mounted on the tubing imparts a stress wave oracoustic pulse onto the tubing string.

Typically, drillers will utilize one of a wireline system, a mud-pulsesystem, an EM system and an acoustic system, most often either an EMsystem or a mud-pulse system. Depending on the nature of the drillingtask, it is often more favourable to use EM due to its relatively fasterdata rate when compared to mud-pulse. However, if a signal is lost dueto the presence of the aforementioned geological conditions, the rigmust be shut down and the drill string tripped to swap the EM systemwith an alternative system such as a mud-pulse system which, althoughslower, is generally more reliable. The drill string would then need tobe re-assembled and drilling restarted. The inherent downtime whiletripping the drill string can often be considerable and thusundesirable.

In general, one problem associated with mud-pulse telemetry is that itcan only be used during the drilling operation as it relies on the flowof mud in the mud-column. When drilling is interrupted, e.g. when addinga sub to the drill string, there is no medium to transmit data.

It is therefore an object of the present invention to obviate ormitigate at least one of the above-mentioned disadvantages.

SUMMARY

In one aspect, there is provided a method for transmitting data fromdownhole in a wellbore being drilled in an earth formation to a surfacestation, the wellbore having a drill string, the method comprising:intercepting a data signal from a directional module indicative of atleast one parameter acquired from at least one sensor; amplifying thedata signal to generate an electromagnetic (EM) signal; transmitting anEM transmit signal through the earth formation by applying the EM signalacross a region of isolation in the drill string; receiving at a surfacesystem, the EM transmit signal; measuring the EM transmit signal withrespect to a reference to generate a received signal; conditioning thereceived signal and converting the received signal to an emulated pulsesignal compatible with a pulse decoder; and transmitting the emulatedpulse signal to the pulse decoder to be decoded by the pulse decoder forsubsequent use.

In another aspect, there is provided a measurement while drilling (MWD)system for transmitting data from downhole in a wellbore being drilledin an earth formation to a surface station, the wellbore having a drillstring, the system comprising: a controller module for intercepting adata signal from a directional module indicative of at least oneparameter acquired from at least one sensor; an amplifier module foramplifying the data signal to generate an electromagnetic (EM) signaland for transmitting an EM transmit signal through the earth formationby applying the EM signal across a region of isolation in the drillstring; and a surface system for receiving the EM transmit signal,measuring the EM transmit signal with respect to a reference to generatea received signal, conditioning the received signal, converting thereceived signal to an emulated pulse signal compatible with a pulsedecoder, and transmitting the emulated pulse signal to the pulse decoderto be decoded by the pulse decoder for subsequent use.

In yet another aspect, there is provided a battery assembly for ameasurement while drilling (MWD) tool string, the battery assemblycomprising; a battery barrel configured to be removably attachable ateach end to other modules in the tool string; a battery comprising afirst end and a second end, the first end and second end being visuallyand physically distinguishable from each other to encourage loading thebattery into the battery barrel in a single orientation; and at leastone retention mechanism attached to the interior of the battery barrelto centre the battery in the battery barrel.

In yet another aspect, there is provided a method for transmitting datafrom downhole in a wellbore being drilled in an earth formation to asurface station, the wellbore having a drill string, the methodcomprising: intercepting a data signal from a directional moduleindicative of at least one parameter acquired from at least one sensor;if instructed to operate according to pulse telemetry, directing thedata signal to a pulse module to generate a pulse signal andtransmitting the pulse signal through a mud column in the drill string;if instructed to operate according to electromagnetic (EM) telemetry,amplifying the data signal to generate an EM signal, transmitting an EMtransmit signal through the earth formation by applying the EM signalacross a region of isolation in the drill string; receiving at a surfacesystem, either the EM transmit signal or the pulse signal according to atelemetry mode; if instructed to operate according to pulse telemetry,directing the pulse signal to a pulse decoder to be decoded by the pulsedecoder for subsequent use; and if instructed to operate according to EMtelemetry, measuring the EM transmit signal with respect to a referenceto generate a received EM signal, conditioning the received EM signal,converting the received EM signal to an emulated pulse signal compatiblewith the pulse decoder, and transmitting the emulated pulse signal tothe pulse decoder to be decoded by the pulse decoder for subsequent use.

BRIEF DESCRIPTION OF THE DRAWINGS

An embodiment of the invention will now be described by way of exampleonly with reference to the appended drawings wherein:

FIG. 1 is a schematic view of a drilling system and its environment;

FIG. 2( a) is an external plan view of a downhole portion of a mud pulsetool drill string configuration.

FIG. 2( b) is an external plan view of a downhole portion of an EM tooldrill string configuration.

FIG. 3( a) is an external plan view of a mud pulse tool stringy

FIG. 3( b) is an external plan view of a EM tool string.

FIG. 4 is a sectional view of a region of isolation in the EM toolstring of FIG. 3( b) along the line IV-IV showing the EM tool stringpositioned therein.

FIG. 5 is an exploded perspective view of a gap sub-assembly.

FIG. 6 is an exploded view of a power supply.

FIG. 7 is a pair of end views of the battery barrel of FIG. 6.

FIG. 8 is a sectional view along the line VIII-VIII shown in FIG. 6.

FIG. 9 is a schematic diagram showing data flow from a directionalmodule to a surface station via an EM transmitter module in an EM MWDsystem.

FIG. 10 is a schematic diagram of the EM transmitter module shown inFIG. 9.

FIG. 11 is a schematic diagram of a surface station utilizing aconventional pulse telemetry system.

FIG. 12 is a schematic diagram of the EM surface system shown in FIG. 9.

FIG. 13 is a plot showing signal propagation according to thearrangement shown in FIG. 9.

FIG. 14 is a flow diagram illustrating an ELM data transmission in theEM MWD system shown in FIG. 9.

FIG. 15 is an external plan view of a downhole portion of an EM andpulse dual telemetry tool drill string configuration.

FIG. 16 is an external plan view of an EM and pulse dual telemetry toolstring.

FIG. 17 is a schematic diagram showing data flow in an EM and pulse dualtelemetry MWD system.

FIG. 18 is a schematic diagram of the EM transmitter module shown inFIG. 17.

FIG. 19 is a schematic diagram of the EM surface system shown in FIG.17.

FIG. 20( a) is a flow diagram illustrating a data transmission using EMand pulse telemetry in the EM and pulse dual telemetry MWD system shownin FIG. 17.

FIG. 20( b) is a flow diagram continuing, from B in FIG. 20( a).

FIG. 20( c) is a flow diagram continuing from C FIG. 20( a).

DETAILED DESCRIPTION OF THE DRAWINGS

The following describes, in one embodiment, an MWD tool providing EMtelemetry while utilizing existing pulse tool modules. In general, an EMsignal is generated by 8 repeating an amplified version of aconventional pulse signal that is intended to be sent to a pulse module,and transmitting this repeated signal to the surface in an EMtransmission. In this way, the same components can be used withoutrequiring knowledge of the encoding scheme used in the pulse signal.Therefore, the following system is compatible with any existing downholedirectional module that generates a signal for a pulse module. The pulsesignal can be intercepted, amplified, and sent to an EM surface systemby applying a potential difference across a region of isolation in thedrill string. The EM surface system receives, conditions and convertsthe received signal into a signal which is compatible with aconventional surface pulse decoder. In this way, existing software anddecoding tools already present in the pulse surface decoder can beutilized while providing EM telemetry capabilities.

In another embodiment, the following provided dual pulse and EMtelemetry capabilities by using a multiplexing scheme to direct thepulse signal to either the pulse module for transmission using pulsetelemetry or to the EM transmitter module for transmission using EMtelemetry. At the surface, the EM surface system receives either signaland routes the appropriate signal to the pulse decoder. The pulsedecoder is unable to distinguish between telemetry modes enablingexisting software and hardware offered by a pulse system can be used. Itwill be appreciated that the following examples are for illustrativepurposes only.

Drilling Environment

Referring therefore to FIG. 1, a drilling rig 10 is shown in situ at adrilling site 12. The rig 10 drills a wellbore 14 into an earthformation 16. The wellbore 14 is excavated by operating a drill bit 18disposed at a lower end 19 of a drill string 20. The drill string 20 issupported at an upper end 21 by drilling equipment 22. As the bit 18drills into the formation 16, individual drill rods 24 are added to thedrill string 20 as required. In the example shown in FIG. 1, the drillbit 18 is driven by a fluid or mud motor 26. The mud motor 26 is poweredby having the drilling equipment 22 pump drill fluid, hereinafterreferred to as “mud”, through a hollow conduit 28 defined by interiorportions of the connected subs 24. The column of fluid held in theconduit 28 will hereinafter be referred to as a “mud column” andgenerally denoted by the character “M”.

An MWD tool 30 is located within the drill string 20 toward its lowerend 19. The MWD tool 30 transmits data to the surface to a remote MWDsurface station 34 The data transmitted to the surface is indicative ofoperating conditions associated with the drilling operation. In oneembodiment, the MWD tool 30 transmits the data to a pulse tool surfacesystem 32 via an EM surface system 38 using EM telemetry as explainedbelow.

The EM surface system 38 is used to receive, condition and convert datatransmitted in an EM signal such that the conditioned data is compatiblewith the pulse tool surface system 32. The EM surface system 38 thusacts as an EM signal conditioner and is configured to interface with thepulse decoder 32. Normally, a pressure transducer on the drillingequipment interfaces with the pulse decoder 32 and thus the interfacebetween the EM surface system 38 and the pulse decoder 32 is preferablysimilar to the interface between the pulse decoder 32 and a connectorfrom a data cable extending from the transducer. The pulse decoder 32 isconnected to a computer interface 36, e.g. a personal computer in thesurface station 34, to enable a user to interact with the MWD tool 30remotely. The pulse decoder 32 also outputs a decoded signal to a rigfloor display 45 via a data connection 44. Accordingly, the MWD tool 30shown in FIG. 1 is configured to interface with and operate usingexisting mud pulse modules from an existing pulse MWD system as will beexplained in greater detail below.

The EM transmission is generated by creating a potential differenceacross a region of isolation 29 in the drill string 20 and is formed bygenerating an electromagnetic (EM) field F which propagates outwardlyand upwardly through the formation 16 to the surface and creating andtransmitting a return signal S through the drill string 20. A conductivemember 50, typically an iron stake driven into the formation 16,conducts the formation signal through a data connection 52 to the EMsurface system 38 and the return signal is transmitted from the surfacestation 34 over line 41 to a connection on the drill rig 12. As can beseen in FIG. 1, the negative dipole for the EM signal is provided by aconnection to the drill string 20 at a location which is above theregion of isolation 29 and the positive dipole for the EM signal isprovided by a connection to the drill string 20 at a location which isbelow the region of isolation 29. It will be appreciated that eithersignal (formation or drill string) can be the EM signal or the returnsignal, however the arrangement shown in FIG. 1 is preferred since thedrill string 20 typically provides a better reference than the formation16.

In another embodiment, the MWD tool 30 provided dual telemetrycapabilities thus capable of transmitting data to the surface receiverstation 34 using either EM telemetry (as discussed above), or mud pulsetelemetry by transmitting data through the mud column M by way of aseries of pressure pulses. The pressure pulses are received by thepressure transducer, converted to an appropriate compatible signal (e.g.a current signal) which is indicative of the information encoded in thepressure pulses, and transmitted over a data cable directly to the pulsedecoder 32 as will be explained in greater detail below.

MWD Tool—Downhole Configuration

Referring to FIG. 2( a), a conventional downhole drill stringconfiguration for a mud pulse MWD tool string 80 is shown (see FIG. 3(a) for pulse tool string 80). An example of such a mud pulse MWD tool isa Tensor™ MWD tool sold by GE Energy™. The conventional mud pulse drillstring configuration comprises a drill bit 18 driven by a mud motor 26connected thereto. Connected to the mud motor 26 is a universal bottomhole offset (UBHO) 60, which internally provides a tool string landingpoint for the pulse tool string 80. Connected to the UBHO 60 is theserially connected drill rods 20 forming the upstream portion 62 of thedrill string 20. The upstream portion 62 of the drill string 20 istypically formed using a few non-magnetic drill rods to provide anon-magnetic spacings between magnetically sensitive equipment and theother drill rods, which can be magnetic.

Referring to FIG. 2( b), a downhole drill string configuration for an EMMWD tool string 100 is shown (see FIG. 3( b) for EM tool string 100). Itcan be seen in FIG. 2( b) that the drill bit 18, mud motor 26 and UBHO60 are configured in the same way shown in FIG. 2( a), however,interposed between the UBHO 60 and the upstream portion 62 of the drillstring 20, is the region of isolation 29. In one embodiment, the regionof isolation 29 comprises a first sub-assembly 64 connected to a secondsub-assembly 67, wherein the first sub assembly 64 is comprised of afirst sub 65 and second sub 66 isolated from each other by a first noneconductive ring 70 and the second sub-assembly 67 is comprised of athird sub 68 and fourth sub 69 isolated from each other by a secondnon-conductive ring 72. The EM tool string 100 is preferably alignedwith the region of isolation 29 such that a tool isolation 102 in the EMtool string 100 is situated between the first and second non-conductiverings 70, 72. However, it can be appreciated that the region ofisolation 29 is used to isolate the drill string 20 and thus the toolisolation 102 may be above or below so long as there is a separationbetween points of contact between the tool string 100 and the drillstring 20 as will be discussed below. As will also be discussed below,the EM tool string 100 is configured to interface with the existing UBHO60 such that the EM tool string 100 can be used with the existingmodules in a conventional pulse tool string 80 such as those included ina GE Tensor™ tool.

The pulse tool string 80 is shown in greater detail in FIG. 3( a). Thepulse tool 22 string 80 is configured to be positioned within the drillstring configuration shown in FIG. 2( a). The pulse tool string 80comprises a landing bit 82 which is keyed to rotate the pulse toolstring 80 about its longitudinal axis into a consistent orientation asit is being landed. The landing bit 82 includes a mud valve 84 that isoperated by a mud pulse module 86 connected thereto. In normal pulsetelemetry operation, the mud valve 84 is used to create pressure pulsesin the mud column M for sending data to the surface. A first battery 88,typically a 28 V battery is connected to the mud pulse module through amodule interconnect 90. The module interconnect 90 comprises a pair ofbow springs 92 to engage the inner wall of drill string 20 and centerthe pulse too string 80 within the drill string 20. The bow springs 92are flexible to accommodate differently sized bores and are electricallyconductive to provide an electrical contact with the drill string 20.The interconnects 90 are typically rigid while accommodating minimalflexure when compared to the rigidity of the tool string 100. Otherinterconnects (not shown) may be used, which are not conductive, wherean electrical contact is not required such other interconnects are oftenreferred to as “X-fins”.

Another module interconnect 90 is used to connect the first battery 88to a direction and inclination module 94. The direction and inclinationmodule 94 (hereinafter referred to as the “directional module 94”)acquires measurement data associated with the drilling operation andprovides such data to the pulse module 86 to convert into a series ofpressure pulses. Such measurement data may include accelerometer data,magnetometer data, gamma data etc. The directional module 94 comprises amaster controller 96 which is responsible for acquiring the data fromone or more sensors and creating, a voltage signal, which is typically adigital representation of where pressure pulses occur for operating, thepulse module 86.

Yet another module interconnect 90 is used to connect a second battery98, typically another 28 V battery, to the directional module 94. Thesecond battery 98 includes a connector 99 to which a trip line can beattached to permit tripping the tool string 80. The tool string 80 canbe removed by running a wireline down the bore of the drill string 20.The wireline includes a latching mechanism that hooks onto the connector99 (sometimes refer-red to as a “spearpoint”). Once the wireline islatched to the tool string, 80, the tool string 80 can be removed bypulling the wireline through the drill string 20. It will be appreciatedthat the tool string 80 shown in FIG. 3( a) is only one example and manyother arrangements can be used. For example, additional modules may beincorporated and the order of connection may be varied. Other modulesmay include pressure and gamma modules, which are not typically attachedabove the second battery 98 but could be. All the modules are designedto be placed anywhere in the tool string 80, with the exception of thepulse module 86 which is located at the bottom in connection with thepulser 84.

Referring now to FIG. 3( b), the EM tool string 100 is shown. The EMtool string 100 is configured to be positioned within the downhole drillstring configuration shown in FIG. 2( b). The EM tool string 100comprises a modified landing bit 104 that is sized and keyed similar tothe landing bit 82 in the pulse tool string 80 but does not include themud valve 84. In this way, the EM tool string 100 can be oriented withinthe drill string 20 in a manner similar to the pulse tool string 80. Inthis embodiment, an EM transmitter module 106 is connected to themodified landing bit 104 in place of the mud pulse module 86. The EMtransmitter module 106 includes electrical isolation 102 to isolate anupstream EM tool portion 108 from a downstream EM tool portion 110. Theelectrical isolation 102 can he made from any non-conductive materialsuch as a rubber or plastic. A quick change battery assembly 200 (e.g.providing 14 V) may be used in place of the first battery 88 discussedabove, which is connected to the EM transmitter module 106 using amodule interconnect 90. It will be appreciated that although the quickchange battery assembly 200 is preferable, the first battery 88described above may alternatively be used. The directional module 94 andsecond battery 98 are connected in a manner similar to that shown inFIG. 3( a) and thus details of such connections need not be reiterated.

It can therefore be seen that downhole, a conventional pulse tool string80 can be modified for transmitting EM signals by replacing the landingbit 82 and pulse module 86 with the modified landing bit 104 and EMtransmitter module 106 while utilizing the other existing modules. Themodified landing bit 104 enables the ENM transmitter module 106 to beoriented and aligned as would the conventional pulse module 86 byinter-facing with the UBHO 60 in a similar fashion.

Region of Isolation—Gap Sub-Assembly

The placement of the EM tool string 100 within the conduit 28 of thedrill string 20 is shown in greater detail in FIG. 4. As discussedabove, the EM tool string 100 is aligned with the region of isolation29, and the region of isolation 29 comprises a first sub-assembly 64connected to a second sub-assembly 67, wherein the first sub-assembly 64comprises first and second subs 65, 66 and the second sub-assembly 67comprises third and fourth subs 68, 69. As can be seen, the shoulders ofthe subs 65 and 66 are separated by a non-conductive ring 70, and thethreads of the subs 65 and 66 are separated by a non-conductive layer71. Similarly, the shoulders of the subs 68 and 69 are separated byanother non-conductive ring 72, and the threads of the subs 68 and 69are separated by another non-conductive layer 73. The rings 70 and 72are made from a suitable non-conductive material such as a ceramic.Preferably, the rings 70 and 72 are made from either Technox™ orYTZP-Hipped™, which are commercially available ceramic materials thatpossess beneficial characteristics such as high compressive strength andhigh resistivity. For example, Technox™ 3000 grade ceramic has beenshown to exhibit a compressive strength of approximately 290 Kpsi andexhibit a resistivity of approximately 10⁹ Ohm·cm at 25° C.

The subs each have a male end or “pin”, and a female end or “box”. Forconstricting the region of isolation 29, the pins and boxes that matetogether where the ceramic ring, 70, 72 is placed should be manufacturedto accommodate the ceramic rings 70, 72 as well as other insulativelayers described below. To accommodate the rings 70, 72, the pin end ofthe subs are machined. Firstly, the shoulder (e.g. see 59 in FIG. 5) ismachined back far enough to accommodate the ceramic ring 70, 72. It hasbeen found that using, a ½″ zirconia ring with a ½″ reduction in theshoulder is particularly suitable. The pin includes a thread that may becustom or an API standard. To accommodate the isolation layers 71, 73,the thread is further machined to be deeper than spec to make room forsuch materials. It has been found that to accommodate the layers 71 and73 described in detail below, the pins can be machined 0.009″ to 0.0010″deeper than spec. The shoulders are machined back to balance the torqueapplied when connecting the subs that would normally be accommodated bythe meeting of the shoulders as two subs come together.

The thread used on the pins is preferably an H90 API connection or anSLH90 API connection due to the preferred 90° thread profile with arelatively course. This is preferred over typical 60° thread profiles.It will be appreciated that the pins can be custom machined to include acourse thread and preferably 90° thread profile. To achieve the sameeffect as the H90 API connection, a taper of between 1.25″ and 3″ perfoot should be used. In this way, even greater flexibility can beachieved in the pin length, diameter and changes throughout the taper.

In one embodiment, the insulative layers 71, 73 comprise the applicationof a coating, preferably a ceramic coating, to the threads of the pinsto isolate subs 65 from sub 66 and sub 68 from sub 69. A suitablecoating is made from Aluminium Oxide or Titanium Dioxide. This locks thecorresponding subs together to provide complete electrical isolation.When using a ceramic coating, the pin should be pre-treated, preferablyto approximately 350° C. Also when applying the ceramic coating, the pinshould be in constant rotation and the feed of the applicator gun shouldbe continuous and constant throughout the application process. It willbe appreciated that any insulative coating can be applied to thethreads. As noted above, the threads are manufactured or modified toaccommodate the particular coating that is used, e.g., based on thestrength, hardness, etc. of the material used and the clearance neededfor an adequate layer of isolation.

In another embodiment, after application of the ceramic coating, a layerof electrical tape or similar thin adhesive layer can be included in theinsulative layers 71 and 73 to add protection for the ceramic coatingfrom chipping or cracking from inadvertent collisions. The electricaltape provides a smooth surface to assist in threading the subs togetherwhile also providing a layer of cushioning.

The insulative layers 71 and 73 can, in another embodiment, alsocomprise a cloth or wrapping made from a fabric such as, Vectran,Spectra, Dyneema, any type of Aramid fiber fabric, any type of ballisticfabric, loose weave fabrics, turtle skin weave fabrics to name a few. Ingeneral, a material that includes favourable qualities such as hightensile strength at low weight, structural rigidity, low electricalconductivity, high chemical resistance, low thermal shrinkage, hightoughness (work-to-break), dimensional stability, and high cutresistance is preferred. In general, the insulative layers 71 and 73 andthe rings 70 and 72 provide electrical isolation independent of thematerial used to construct the subs 65, 66, 68 and 69. However,preferably the subs 65, 66, 68 and 69 are made from a non-magneticmaterial so as to inhibit interference with the electromagnetic field F.

The insulative layers 71, 73 may further be strengthened with an epoxytype adhesive which serves to seal the sub assemblies 64, 67. Inaddition to the epoxy adhesive, a relief 179 may be machined into thebox of the appropriate subs as seen in the enlarged portion of FIG. 4.The relief 179 is sized to accommodate a flexible washer 180, preferablymade from polyurethane with embedded rubber o-rings 182. The washer 180is placed in the relief such that when the pin is screwed into the box,the outside shoulders 597 75 (see FIG. 5 also) engage the ceramic ring70 or 727 an inside shoulder also enrages where the washer 180 isseated. The polyurethane is preferably a compressible type, which canadd significant safeguards in keeping moisture film seeping into thethreads. The addition of the o-rings 182 provides a further defence incase of cracking or deterioration of the polyurethane or similarmaterial in the washer 180. In this way, even if the epoxy seal breaksdown, a further layer of protection is provided. This can prolong thelife of the region of isolation 29 and can prevent moisture fromshorting out the system.

FIG. 5 illustrates an exploded view of an exemplary embodiment of thefirst sub-assembly 64 utilizing a ceramic coating and a wrapping ofwoven fabric in addition to the other insulative layers discussed above.In a preferred assembly method, the sub-assembly 64 is assembled byapplying the ceramic coating to the pin of the sub 65 and then applyinga layer of electrical tape (not shown). The ceramic ring 70 is then slidover the male-end of the first sub 65 such that it is seated on theshoulder 59. The epoxy may then be added over the electrical tape toprovide a moisture barrier. A wax string may also be used if desired.The washer 180 is then inserted into the relief 179. The wrapping 71 ais then wrapped clockwise around the threads of the pin of the sub 65over the electrical tape, as the female-end of the second sub 66 isscrewed onto the male-end of the first sub 65, until the shoulder 75engages the ring 70. As the female-end of the second sub 66 is screwedonto the male-end of the first sub 65. In this way, the ring 70 provideselectrical isolation between the shoulders 59 and 75, and the cloth 71a,ceramic, tape and epoxy provides electrical isolation between thethreads. As such, the sub 65 is electrically isolated from the sub 66.It will be appreciated that the second sub-assembly 67 call be assembledin a similar manner.

It will be appreciated that all of the above insulative materials can beused to provide layer 71 as described, as well as any combination of oneor more. For example, the ceramic coating may be used on its own or incombination with woven fabric 71 a. It can be appreciated that eachlayer provides an additional safeguard in case one of the other layersfalls. When more than one insulative material is used in conjunctionwith each other, the isolation can be considered much stronger and moreresilient to environmental effects.

As shown in FIG. 4 (also seen in FIG. 2( b)), the subassemblies 64 and67 are connected together without any electrical isolation therebetween.The upstream tool portion 108 is electrically connected to the drillstring 20 at contact point 74 and the downstream tool portion 110 iselectrically connected to the drill string 20 at contact point 76provided by the interface of the modified landing bit 104 and the UBHO60. It can be seen that the sub-assemblies 64 and 67 should be sizedsuch that when the modified landing bit 76 is seated in the UBHO 60, thetool isolation 102 is between the non-conductive rings 70 and 72 andmore importantly, such that the bow springs 92 contact the drill string20 above the region of isolation 29. This enables the electric field Fto be created by creating the positive and negative dipoles.

Power Supply—Quick Change Battery

As discussed above, the EM tool string 100 may include a quick changebattery assembly 200. The quick change battery assembly 200 can provide14V or can be configured to provide any other voltage by adding orremoving battery cells. Preferably, the quick change battery assembly200 is connected to the other modules in the EM tool string 100 as shownin FIGS. 6-8. Referring first to FIG. 6, an exploded view is providedshowing the connections between the battery assembly 200 and the EMImodule 104 using module interconnect 90. In the example shown, thebattery assembly 200 includes a battery barrel 208 that is connecteddirectly to the module interconnect 90 at one end 201 and thus the end201 includes a similar interconnection. A bulkhead 202 is connected tothe other end 203 of the battery barrel 208 to configure the end 203 forconnection to the module interconnect 90 attached further upstream ofthe directional module 94. Typically, another battery assembly 98 is inturn connected to the directional module 94 as discussed above.

The battery barrel 208 houses a battery 210. The battery 210 includes anumber of battery cells. It will be appreciated that the barrel 208 canbe increased in length to accommodate longer batteries 210 having agreater number of cells. The battery 210 in this example includes alower 45 degree connector 212 and an upper 90 degree connector 214. Thelower connector 212 preferably includes a notch 213, which is oriented45 degrees from the orientation of a notch 215 in the upper connector214. The notches 213 and 215 are shown in greater detail in FIG. 7. Thenotches 213 and 215 are different from each other so as to bedistinguishable from each other when the battery 210 is installed andthus minimize human error during assembly. As can be seen in FIG. 7, thenotches 213 and 215 are generally aligned with respective retentionmechanisms 220 and 222. The mechanisms 220 and 222 are preferably pinassemblies that maintain the position of the battery 210 in the barrel208.

The tipper end 214 of the battery 210 is preferably centered in thebarrel 208 using a bushing 216, as shown in FIGS. 7 and 8 (wavy line inFIG. 7). The bushing 216 is arranged along the inside of the barrel 208at end 203 and situates the upper connector 214 to inhibit movement andpotential cracking of the battery casing.

The battery 210 can be changed in the field either by removing thebattery barrel 208 from the EM module 104 and the directional module 94or, preferably, by disconnecting the directional module 94 from thebulkhead 202 (which disconnects the upper connector 214); disconnectingthe lower connector 212 from the EM module 104 by pulling the battery210 from the barrel 208 and bulkhead 202; replacing the battery 210 witha new battery; and reassembling the EM module 104, barrel 208 anddirectional module 94. Since the tipper connector 214 and lowerconnector 212 are visually different, the nature of the battery 210should assist the operator in placing the battery 210 in the barrel 208in the correct orientation. Similarly, since, in this example, only theend 203 connects to a bulkhead 202, if the entire battery assembly 200is removed, the ends 201, 201 3 should be obviously distinguishable tothe operator.

It can therefore be seen that the battery 210 can be readily removedfrom the barrel 208 when a new battery is to replace it. The arrangementshown in FIGS. 6-8 thus enables a “quick change” procedure to minimizethe time required to change the battery 210, which can often be requiredin poor environmental conditions. It can be appreciated that minimizingdowntime increases productivity, which is also desirable.

MWD Tool—First Embodiment

A schematic diagram showing data flow in one embodiment, from a seriesof downhole sensor 120 to the surface station 34 using the EM toolstring 100 is shown in FIG. 9. The sensors 120 acquire measurements forparticular downhole operating parameters and communicate themeasurements to the master controller 96 in the directional module 94 bysending an arbitrary m number of inputs labelled IN₁, IN₂, . . . ,IN_(m) from all arbitrary ill number of sensors 120. The mastercontroller 96 is part of an existing pulse MWD module, namely thedirectional module 94, as discussed above. The master controller 96generates and outputs a pulse transmission signal labelled P_(tx) whichis an encoded voltage pulse signal.

Generally, encoding transforms the original digital data signal into anew sequence of coded symbols. Encoding introduces a structureddependency among the coded symbols with the aim to significantly improvethe communication performance compared to transmitting uncoded data. Inone scheme, M-ary encoding is used (e.g. in the GE Tensor™ tool), whereM represents the number of symbol alternatives used in the particularencoding scheme.

The encoded data is then modulated, where, modulation is a step ofsignal selection which converts the data from a sequence of codedsymbols (from encoding) to a sequence of transmitted signalalternatives. In each time internal, a particular signal alternative issent that corresponds to a particular portion of the data sequence. Forexample, in a binary transmission, where two different symbols are used,the symbol representing a “high” or “1”, will be sent for every “1” inthe sequence of binary data. In the result, a waveform is created thatcarries the original analog data in a binary waveform. Where M isgreater than 2, the number of symbol alternatives will be greater andthe modulated signal will therefore be able to represent a greateramount data in a similar transmission.

M-ary encoding typically involves breaking up any data word intocombinations of two (2) and three (3) bit symbols, each encoded bylocating a single pulse in one-of-four or one-of-eight possible timeslots. For example, a value 221 encodes in M-ary as 3, 3, 5. The 3, 3, 5sequence comes from the binary representation of 221, which is11|011|101. In this way, the first 3 comes from the 2-bit symbol 11, thesecond 3 comes from the 3-bit symbol 011, and the 5 comes from the 3-bitsymbol 101.

It can be appreciated that different directional modules 94 may usedifferent encoding schemes, which would require different decodingschemes. As will be explained below, the EM transmitter module 106 isconfigured to intercept and redirect an amplified version of P_(tx) suchthat the EM transmitter module 106 is compatible with any directionalmodule 94 using, any encoding scheme. In this way, the EM transmittermodule 106 does not require reprogramming to be able to adapt to othertypes of directional modules 94. This provides a versatile module thatcan be interchanged with different mud pulse systems with minimumeffort.

The output P_(tx) is a modulated voltage pulse signal. The modulatedsignal is intended to be used by the pulse module 86 to generate asequence of pressure pulses according to the modulation scheme used.However, in the embodiment shown in FIG. 9, the EM transmitter module106 intercepts the modulated voltage signal. The EM transmitter module106 includes an EM controller module 122 and an EM amplifier module 124.The controller module 122 intercepts P_(tx) and also outputs a flowcontrol signal f and communication signal Comm. The flow control signalf is used to determine when “flow” is occurring in the drilling mud.Ultimately, when fluid is being pumped downhole (“flow oil” condition),drilling has commenced and data is required to be transmitted to the surface. Although EM telemetry does not require “flow” in the drilling mudto be operational, existing directional modules 94 are designed to workwith pulse modules 86. As such, existing directional modules 94 requireflow in order to operate since pressure pulses cannot be created in astatic fluid column M. Moreover, when flow stops, the drill string 20and the MWD tool 30 become “stable” and allow other more sensitivemeasurements to be acquired (e.g. accelerometer and magnetometer data),stored and transmitted on the next “flow on” event.

The flow control signal f in the EM controller module 122 is used toinstruct the master controller 96 when a consistent vibration has beensensed by the vibration switch 128. The master controller 96 may thenuse the flow signal f to activate its internal “flow oil” status. TheComm signal is used to allow communication between the EM controllermodule 122 and the master controller 96. Such communication allows theEM controller module 122 to retrieve operational information that theMWD operator has programmed into the master controller 96 before the jobhas commenced, e.g. current limit values.

The EM controller module 120 and EM amplifier module 122 are shown ingreater detail in FIG. 10. The controller module 120 comprises amicrocontroller 126, which receives the encoded P_(tx) signal, andgenerates the flow control signal f. The flow signal f is generated inresponse to an output from a vibration switch 128 connected to themicrocontroller 126. The vibration switch 128 responds to vibrations inthe drill string 20 generated by mud flow, which is generated by a mudpump included in the surface drilling equipment 22. The microcontroller126 also communicates with a serial driver 130 to generate the Commsignal. In a GE Tensor™ tool, the Comm signal is referred to as theQbus.

Optionally, the controller module 120 may also include a clock 132 fortime stamping information when such information is stored in the EMcontroller module log memory 134. This enables events stored in thelogging memory 134 to be correlated to events stored in memory in themaster controller 96 or events that occur on the surface, once thememory is downloaded. The EM controller module 122 is thus capable oflogging its own operational information (e.g. current limits, resetsetc.) and can log information it receives via the Comm line connected tothe master controller 96 (e.g. mode changes).

A data connection D may also be provided for communicating between theEM controller module 122 and an optional EM receiver (not shown) thatcan be included in the EM transmitter module 106. This can beimplemented for providing bidirectional communication allowing tile EMtransmitter module 106 to receive commands/information from the surfacesystem 34 via EM signals and relay the information to the EM controllermodule 122.

The microcontroller 126 passes the encoded pulse signal P_(tx) to the EMamplifier module 124. The microcontroller 126 also outputs voltage andcurrent limit signals V_(lim) and I_(lim) respectively that are used bythe amplifier module 124 to control a voltage limiter 136 and a currentlimiter 13S respectively. Tile EM signal is fed into an amplifier 140 inthe amplifier module 124 in order to repeat an amplified version of theP_(tx) signal in an EM transmission to the surface.

A current sense module 142 is also provided, which senses the current inthe EM signal that is to be transmitted, namely EM_(tx) as feedback forthe current limiter and to generate a current output signal I_(out) forthe controller module 122. The amplified EM signal labelled EM′ ismonitored by the voltage limiter 136 and output as V_(out) to thecontroller module 122. As can be seen in FIG. 9, a connection point 74above the isolation 102 provides a conductive point for return signalEM_(ret), and EM_(tx) is sent to a connection 76 in the UBHO 60, whichas shown in FIG. 3( b) is naturally below the isolation 102.

The EM transmit signal EM_(tx) is the actual EM transmission, and issent through the formation 16 to the surface. The EM return signalEM_(ret) is the return path for the EM transmission along path S throughconnection 144. It will be appreciated that either signal (EM_(tx) orEM_(ret)) can be the signal or the return, however the arrangement shownin FIG. 9 is preferred since the drill string 20 typically provides abetter reference than the formation 16. EM_(tx) propagates through theformation as a result of creation of the positive and negative dipolescreated by the potential difference across the connections 74 and 76,which creates the electric field F. The ground stake 50 conducts the EMsignal and propagates a received signal EM_(rx) along line 52 to thesurface station 34.

The surface station 34, when using, conventional mud pulse telemetry mayinclude the components shown in FIG. 11. A mud pulse signal whichpropagates up through the drilling mud M is received and interpreted bya pressure transducer, which sends a current signal to the pulse decoder32. The pulse decoder 32 then decodes the current signal and generatesan output to send to the PC 36 for the user to interpret, which may alsobe sent to the rig floor display 45. As can be seen in FIG. 9, where theconventional mud pulse system is adapted to transmit using EM telemetry,the EM surface system 38 intercepts the incoming EM signal E_(rx) andgenerates an emulated received pulse signal labelled P_(rx)′. Theemulated pulse signal R_(rx)′ is generated such that the pulse decoder32 cannot distinguish between it and a normal received pulse signalP_(rx). In this way, the pulse decoder 32 can be used as would be usual,in order to generate an output OUT₁ for the PC 36, output OUT₂ for therig floor display 45.

The PC 36 is generally used only for interfacing with the system, e.g.programming the MWD toolstring 100 and pulse decoder 32, and to mimicthe rig floor display 45 so that the operator and directional drillercan see in the surface station 34 what is seen oil the rig 10 withoutleaving the station 34. Optionally, an interface connection 148 may beprovided between the PC 36 and the EM surface system 38 for controllingparameters thereof and to communicate downhole as discussed above. Theoperator may thus use the PC 36 to interface with the EM surface system38 and send changes in the operational configuration by way of anotherEM signal (not shown), which may or may not be encoded in the same wayas the master controller 96, downhole via EM_(ret) and EM_(rx)/EM_(tx).The EM receiver would then receive, decode and communicate configurationchanges to the EM controller module 122. The EM receiver module wouldthus be in communication with EM_(ret) and EM_(tx) downhole.

The EM surface system 38 is shown in greater detail in FIG. 12. Thereceived EM signal EM_(rx) is fed into a first gain amplifier 150 withthe return signal EM_(ret) also connected to the amplifier 150 in orderto provide a ground reference for tile EM signal EM_(rx). The amplifier150 measures the potential difference of the received EM signal EM_(rx)and the ground reference provided by the return signal EM_(ret) andoutputs a referenced signal. The referenced signal is then filtered at afirst filtering stage 151. The first filtering stage 151 may employ aband reject filter, low pass filter, high pass filter etc. The filteredsignal is then fed into a second gain amplifier 152 to further amplifythe signal, which in turn is fed into a second filtering stage 153. Thesecond filtering stage 153 can be used to filter out components thathave not already been filtered in tile first filtering stage 151. Thefiltered signal is then fed to a third gain amplifier 154 in order toperform a final amplification of the signal. It will be appreciated thatthe number of filtering and amplification stages shown in FIG. 12 arefor illustrative purposes only and that any number may be used in orderto provide a conditioned signal. The signal is then fed into a pressuretransducer emulator 158, which converts the filtered and amplifiedvoltage signal into a current signal thus creating emulated pulse signalP_(rx)′. The emulated pulse signal P_(rx)′ is then output to the pulsedecoder 3.

It can be seen in FIG. 12 that the filtering and amplification stages150-154 each include a control signal 160 connected to a user interfaceport 156. The user interface port 156 communicates with the PC 36enabling the user to adjust the gain factors and filter parameters (e.g.cut off frequencies). It will be appreciated that rather than employingconnection 148 to the PC 36, the EM surface system 38 may instead haveits own user interface such as a display and input mechanism to enable auser to adjust the gain and frequency parameters directly from the EMsurface system 38.

Exemplary Data Transmission Scheme—First Embodiment

Referring now to FIGS. 13 and 14, and example data transmission schemefor the embodiment shown in FIGS. 9-12 will now be explained.Measurements are first obtained by one or more of the sensors 120,typically while the equipment 22 is drilling. Measurements can beobtained from many types of sensors, e.g. accelerometers, magnetometers,gamma, etc. As discussed above the sensors 120 feed data signals IN₁,IN₂, . . . , IN_(m) to the master controller 96 in the directionalmodule 94. The master controller 96 encodes the data using itspredefined encoding scheme. As mentioned above, a GE Tensor™ tooltypically utilizes M-ary encoding. Other pulse tools may use a differenttype of encoding. The encoded pulse signal P_(tx) is then output by themaster controller 96. As discussed above, EM controller 122 iscompatible with any type of encoding scheme and is not dependent on suchencoding. As such, the EM transmitter module 106 can be used with anytype of pulse system without requiring additional programming.

The pulse signal P_(tx) is intended to be sent to the pulse module 86but is intercepted by the EM transmitter module 106. Regardless of theencoding scheme being used the microcontroller 126 obtains and redirectsthe pulse signal P_(tx) to the EM amplifier module 124. Themicrocontroller 126 does not decode or have to interpret the pulsesignal P_(tx) in any way and only redirects the signal to the amplifiermodule 124. The amplifier 140 amplifies the P_(tx) signal to createamplified EM signal EM′, which is transmitted from the EM transmittermodule 106 as EM signal EM_(tx) with a return path being provided forreturn signal EM_(ret).

During operation, the amplified signal EM′ is fed through the currentsense module 142 to continuously obtain a current reading for thesignal. This current reading is fed back to the current limiter 138 sothat the current limiter 138 can determine if the amplifier 140 shouldbe adjusted to achieve a desired current. The current and voltage limitand amplification factor are largely dependent on the type of batterybeing used and thus will vary according to the equipment available. Thevoltage of the amplified signal is also monitored by the voltage limiter136 to determine if the amplifier 140 should be adjusted to achieve adesired voltage. The microcontroller 126 also monitors the amplifiedoutput voltage V_(out) and amplified output current I_(out) to adjustthe voltage limit V_(lim) and current limit I_(lim) signals.

The limits are typically adjusted according to predetermined parametersassociated with the directional module 94 which are used in order toincrease or decrease signal strength for different formations and arechanged downhole by instructing the master controller 96 with differentmodes. The EM controller module 122 is used to communicate with themaster controller 96 as discussed above, to determine the active modeand to set the current limit accordingly. Typically, the current limitis set as low as possible for as long as possible to save on powerconsumption, however, this factor is largely dependent on transmissioncapabilities thorough the formation and the available battery power.

During operation, the microcontroller 126 also generates the flow signalf and Comm signal to indicate when flow is detected and to effectcommunication with the master controller 96.

The transmitted EM signal is received at the EM surface system 38 asEM_(rx) and the signal returned via EM_(ret). These signals aretypically in the milli-volt to micro-volt range, which is largelydependent on the depth of the down hole antenna and the formationresistance. The potential difference of these signals is then measuredby the first amplifier 150 and a combined signal amplified and filteredto compensate for attenuation and altering caused by the formation. Theamplified arid filtered signal is then fed into the pressure transduceremulator 158 to convert the voltage pulse sent via EMI telemetry, into acurrent signal. It has been found that for a GE Tensor™ pulse decoder32, a current signal in the range of 4-20 mA is sufficient to mimic thepulse signal P_(rx) normally sent by a pressure transducer. Thisconversion ensures that the emulated pulse signal P_(rx)′ is compatiblewith the pulse decoder 32. This avoids having to create new software andinterfaces while enabling the user to utilize EM telemetry with existingdirectional modules.

The emulated current signal P_(rx)′ is then fed into the pulse decoder32. The pulse decoder 32 then decodes and outputs the informationcarried in the encoded signal to the PC 36 enabling the user in thesurface station 34 to monitor the downhole parameters. Another outputcan also be transmitted simultaneously via line 44 to the rig floordisplay 45 to enable the drilling equipment operators to also monitorthe downhole conditions. FIG. 13 shows an exemplary signal plot at thevarious stages discussed above.

Mode changes can be executed in the downhole tool string bycommunicating from the surface system to the downhole tool string. Someforms of communication can include, but are not limited to, downlinkingand EM transmissions. Downlinking is only one common form ofcommunication, in particular for a GE Tensor™ tool, for changing betweenpre-configured modes in the master controller 96. Downlinking can beperformed by alternating flow on and flow off (pumps on, pumps off) atthe surface, with specific timing intervals, where certain intervalscorrelate to different modes. The flow on and flow off events aredetected by 18 the vibration switch 138 on the EM controller module 122and in turn the flow signal f is toggled accordingly. This is theninterpreted by the master controller 96, which is always monitoring theflow line f for a downlink. Once a downlink has occurred, depending onthe timing interval, the master controller 96 changes to the desiredmode. The EM controller module 122 communicates via the Comm line to themaster controller 96 to determine the correct mode, and adjusts its ownsettings accordingly (e.g. pulse/EM operation—dual telemetry discussedbelow, current limit, etc.). The surface system 38 is also watching forthe flow events and changes its operating mode to match the downholesituation.

The MWD tool 30 shown in FIGS. 9-12 enables a driller to upgrade or addEM capabilities to existing mud-pulse systems. When switching betweentelemetry modes in a single telemetry embodiment, only the pulse module86 and landing bit 82 needs to be removed downhole (along with batteriesas required), and a connection swapped at the surface station 34. Theconnection would be at the pulse decoder 32, namely where a pressuretransducer would normally be connected to the pulse decoder s2. In orderto switch the downhole components between mud-pulse telemetry and EMtelemetry, the drill string 20 could be tripped, however, switching atthe surface can be effected off-site by simply swapping connectors attile pulse decoder 32 and there would be no need to access the rig 10 ordrilling equipment 22 in order to make such a change. The pressuretransducer can thus remain installed in the rig 10 whether EM ormud-pulse telemetry is used. Of course, a wireline could instead be usedrather than tripping the entire drill string 20 to add furtherefficiencies.

It may be noted that when a switch between telemetry modes is madebetween shifts, i.e. when the string 20 is to be tripped anyhow, thedriller will not likely be unduly inconvenienced. The quick changebattery 200 can also be used to save time since it can be swapped in anefficient manner.

MWD Tool—Second Embodiment

In another embodiment, shown in FIGS. 15-20, the MWD tool 30 is adaptedto offer dual telemetry capabilities, in particular, to accommodate bothan EM telemetry mode and mud-pulse telemetry mode without trippingeither or both of the tool string and drill string,. It will beappreciated that in the following description, like elements will begiven like numerals, and modified ones of the elements described abovewill be given like numerals with the suffix “a” to denote modules andcomponents that are modified for the second embodiment.

Referring first to FIG. 15, a downhole drill string configuration forthe second 22 embodiment is shown. As can been seen, the drill bit 18and mud motor 26 are unchanged, as well as the upstream portion 62 ofthe drill string 20 and the region of isolation 29. In order toaccommodate both the EM transmitter module 106 and the pulse module 86in a dual telemetry tool string 170, an elongated, modified UBHO 60 a isused. The modified UBHO 60 a compensates for the increased distancebetween where the tool string 170 lands and where the isolation 102 isin alignment with the region of isolation 29. As shown in FIG. 16, thedual telemetry tool string 170 includes the traditional landing bit 82with the pressure valve 84, which is connected to the pulse module 86. Amodified interconnect 91 is then used to connect the EM transmittermodule 106 to above the pulse module 86. Upstream from the EMtransmitter module 106 is the same as shown in FIG. 3( b) and thus thedetails of which need not be reiterated.

Referring to both FIG. 15 and FIG. 16, it can be seen that in the dualtelemetry tool string 170, the EM transmitter module 106 is spacedfurther from the landing point and the traditional pulse landing bit 82is used. Similar to the EM tool string 100, existing mud pulse modulescan be used with the EM modules to create a dual telemetry MWD tool 30.

FIG. 17 shows an electrical schematic for the second embodiment. It canbe seen that the configuration is largely the same with variousmodifications made to accommodate both telemetry modes. A modifiedcontroller module 122 a, includes a multiplexer 172 to enable the EMtransmitter module 106a to bypass the amplifier module 124 and send thepulse signal P_(tx) directly to the pulse module 84 when operating inpulse telemetry mode. The modified controller module 122 a is shown inFIG. 18. It can be seen that the multiplexer 172 is operated by a signalx provided by a modified microcontroller 126 a to direct P_(tx) eitherto the microcontroller 126 a or bypass to the pulse module 84. A surfacepressure transducer 176 is also shown, which would normally be in fluidcommunication with the mud column M so as to be able to sense thepressure pulses sent by the pulser module 86. The other components shownin FIG. 18 are similar to those discussed above as indicated by thesimilar reference numerals and thus details thereof need not bereiterated.

At the surface, a modified EM surface system 38 a is used as shown inFIG. 19. It can be seen that the filtering and amplification stages150-154, user interface port 156 and emulator 158 are the same as shownin FIG. 12. A surface multiplexer 174 is used to enable either theemulated pulse signal P_(rx)′ to be sent to tile pulse decoder 32 in EMtelemetry mode as discussed above, or the normal pulse signal P_(rx)obtained from the pressure transducer 176. A modified interface signal148 includes a connection to the multiplexer 174 to enable the user tosend a mode control signal y to the multiplexer 174 to change telemetrymodes.

Exemplary Data Transmission Scheme—Second Embodiment

Referring now to FIGS. 20( a), 20(b) and 20(c), an example datatransmission scheme for the second embodiment shown in FIGS. 15-19 willnow be explained. Referring, first to FIG. 20( a), similar to the firstembodiment, data is obtained from the sensors 120 by the mastercontroller 96, and an encoded output is sent to the pulse module 86.Also as before, the EM transmitter module 106 intercepts the encodedsignal P_(tx). When in operation, the microcontroller 126 a is providedwith a mode type, indicating whether to operate in an EM mode or a pulsemode. The telemetry mode can be indicated by downlinking from thesurface system 34.

The microcontroller 126 determines the appropriate mode and if pulsetelemetry is to be used, control signal x is set to 1 such that themultiplexer 172 directs the pulse signal P_(tx) to the pulse module 86as can be seen by following “B” to FIG. 20( b). In the pulse mode, theEM transmitter module 106 does not operate on a signal and thus is idleduring the pulse mode The pulse module 86 uses the transmit pulse signalP_(tx) to generate a series of pressure pulses in the mud column M,which are sensed by the pressure transducer 176 at the surface, wherethey are converted into a current signal and sent to tile surfacestation 34.

As before, the EM surface system 3 8 a intercepts the received pulsesignal P_(rx) and directs the signal to the pulse decoder 32, thusbypassing the EM circuitry. This is accomplished by having the interfacesignal 148 a set the control signal y=1, which causes the multiplexer174 to pick up the pulse signal P_(rx). This is then fed directly intothe pulse decoder 32, where the signal can be decoded and output asdescribed above.

Turning back to FIG. 20( c), if the microcontroller 126 a is instructedto operate in EM telemetry mode, control signal x is set to x=0, whichcauses multiplexer 172 to direct the pulse transmit signal P_(tx) to theamplifier module 124, which can be seen by following “C” to FIG. 20( c).It can be appreciated from FIG. 20( c) that transmission in the EMtelemetry mode operates in the same way as in the first embodiment withthe addition of the interface signal 148 a setting control signal x tox=0, causing the multiplexer 174 to direct the emulated pulse signalP_(rx)′ to the pulse decoder 32. Accordingly, details of such similarsteps need not be reiterated.

Therefore, the use of dual telemetry may be accomplished by configuringa dual telemetry tool string 170 as shown in FIG. 16 with a modified EMtransmitter module 106, and modifying receiver module 38 to include amultiplexer 174. This enables the SKI modules to work with the existingpulse modules. An EM transmission may be used that mimics a mud-pulsetransmission or the original pulse signal used. In the result,modifications to the pulse decoder 32, pulse module 86 or landing bit 82are not required in order to provide an additional EM telemetry modewhile taking advantage of an existing mud-pulse telemetry. Moreover, thedrill string 20 does not require tripping to switch between mud-pulsetelemetry and EM telemetry in the second embodiment.

Further Alternatives

It will be appreciated that the tool strings 100 and 170 can also bemodified to include other modules, such as a pressure module (notshown). For example, a similar arrangement as shown in FIG. 3( b) couldbe realized with the pressure module ill place of the pulse module 86and the modified landing bit 104 in place of the landing bit 82. It willbe appreciated that the tool string 100 may also be modified to includepulse telemetry, EM telemetry and a pressure module by making theappropriate changes to the drill string 20 to ensure that the isolationexists for EM telemetry.

Although the above has been described with reference to certain specificembodiments, various modifications thereof will be apparent to thoseskilled in the art as outlined in the claims appended hereto.

1. A method for transmitting data from downhole in a wellbore beingdrilled in an earth formation to a surface station, said wellbore havinga drill string, said method comprising; intercepting a data signal froma directional module indicative of at least one parameter acquired fromat least one sensor; amplifying said data signal to generate anelectromagnetic (EM) signal; transmitting an EM transmit signal throughsaid earth formation by applying said EM signal across a region ofisolation in said drill string; receiving at a surface system, said EMtransmit signal; measuring said EM transmit signal with respect to areference to generate a received signal; conditioning said receivedsignal and converting said received signal to an emulated pulse signalcompatible with a pulse decoder; and transmitting said emulated pulsesignal to said pulse decoder to be decoded by said pulse decoder forsubsequent use.
 2. The method according to claim 1, wherein saidtransmitting said EM transit signal comprises providing a contact withsaid drill string on one side of said region of isolation to enable saidEM transmit signal to propagate through an earth formation, andproviding another contact with said drill string on the other side ofsaid region of isolation to connect a return path for a return signalfrom said surface system.
 3. The method according to claim 2 whereinsaid return path is provided by said drill string.
 4. The methodaccording to claim 1 comprising communicating with said directionalmodule to control operation thereof in response to sensing vibrations indrilling mud contained by said drill string.
 5. The method according toclaim 1 comprising storing operational information.
 6. The methodaccording to claim 1 comprising sensing current in said EM transmitsignal and adjusting said current using a current limiter.
 7. The methodaccording to claim 1 comprising sensing voltage of said EM transmitsignal and adjusting said voltage using a voltage limiter.
 8. The methodaccording to claim 1 wherein said conditioning comprises one or moregain stages and one or more filtering stages.
 9. The method according toclaim 8 comprising providing a user interface for adjusting parametersassociated with said gain and filtering stages.
 10. The method accordingto claim 1 wherein said emulated pulse signal mimics a pressuretransducer signal normally supplied to said pulse decoder.
 11. Ameasurement while drilling (MWD) system for transmitting data fromdownhole in a wellbore being drilled in an earth formation to a surfacestation, said wellbore having a drill string, said system comprising: acontroller module for intercepting a data signal from a directionalmodule indicative of at least one parameter acquired from at least onesensor; an amplifier module for amplifying said data signal to generatean electromagnetic (EMVI) signal and for transmitting an EM transmitsignal through said earth formation by applying said EM signal across aregion of isolation in said drill string; and a surface system forreceiving said EM transmit signal, measuring said EM transmit signalwith respect to a reference to generate a received signal, conditioningsaid received signal, converting said received signal to an emulatedpulse signal compatible with a pulse decoder, and transmitting saidemulated pulse signal to said pulse decoder to be decoded by said pulsedecoder for subsequent use.
 12. The system according to claim 11 whereinsaid controller module comprises a microcontroller to redirect said datasignal to said amplifier module and a vibration switch for sensingvibrations in drilling mud contained by said drill string, saidmicrocontroller being connected to said directional module forcommunicating therewith to control operation thereof in response tooperation of said vibration switch.
 13. The system according to claim 11wherein said controller module comprises a log memory for storingoperational information.
 14. The system according to claim 13 whereinsaid controller module comprises a clock for time-stamping saidoperational information to enable correlation of said operationalinformation with information stored in said directional module and/orevents occurring at said surface system.
 15. The system according toclaim 11, said amplifier module comprising an amplifier circuitcontrolled by a voltage limiter and a current limiter, and a currentsense circuit for measuring current in said EM transmit signal whereinsaid voltage limiter and said current limiter are controlled accordingto voltage and current respectively of said EM transmit signal.
 16. Thesystem according to claim 11 wherein said surface system comprises oneor more gain stages and one or more filtering stages for providing saidconditioning.
 17. The system according to claim 16 wherein said surfacesystem comprises a user interface for adjusting parameters associatedwith said gain and filtering stages.
 18. The system according to claim11 wherein said surface system comprises a pressure transducer emulatorfor creating said emulated pulse signal, wherein said emulated pulsesignal mimics a pressure transducer signal normally supplied to saidpulse decoder.
 19. A battery assembly for a measurement while drilling(MWD) tool string, said battery assembly comprising: a battery barrelconfigured to be removably attachable at each end to other modules insaid tool string; a battery comprising a first end and a second end,said first end and second end being visually and physicallydistinguishable from each other to encourage loading said battery intosaid battery barrel in a single orientation; and at least one retentionmechanism attached to the interior of said battery barrel to centre saidbattery in said battery barrel.
 20. The battery assembly according toclaim 19 wherein said first and second ends each comprise a differentnotch.
 21. The battery assembly according to claim 20 wherein said firstend comprises a 45 degree notch and said second end comprises a 90degree notch.
 22. The battery assembly according to claim 19 whereinsaid retention mechanism is a bushing surrounding at least one of saidfirst and second ends.
 23. A method for transmitting data from downholein a wellbore being drilled in an earth formation to a surface station,said wellbore having a drill string, said method comprising:intercepting a data signal from a directional module indicative of atleast one parameter acquired from at least one sensor; if instructed tooperate according to pulse telemetry, directing said data signal to apulse module to generate a pulse signal and transmitting said pulsesignal through a mud column in said drill string; if instructed tooperate according to electromagnetic (EM) telemetry, amplifying saiddata signal to generate an EM signal, transmitting an EM transmit signalthrough said earth formation by applying said EM signal across a regionof isolation in said drill string; receiving at a surface system, eithersaid EM transmit signal or said pulse signal according to a telemetrymode; if instructed to operate according to pulse telemetry, directingsaid pulse signal to a pulse decoder to be decoded by said pulse decoderfor subsequent use; and if instructed to operate according to EMtelemetry, measuring said EM transmit signal with respect to a referenceto generate a received EM signal, conditioning said received EM signal,converting said received EM signal to an emulated pulse signalcompatible with said pulse decoder, and transmitting said emulated pulsesignal to said pulse decoder to be decoded by said pulse decoder forsubsequent use.
 24. A gap sub-assembly for electrically isolating anupstream portion of a drill string from a downstream portion of saiddrill string, said sub-assembly comprising: a first sub and a secondsub; a first non-conductive ring interposed between said first andsecond sub; and a first insulative layer interposed between respectivethreads of a male end of said first sub and a female end of said secondsub, said first insulative layer comprising a ceramic coating; whereinsaid insulative layer is applied to said male end of said first sub andsaid female end of said second sub is then connected to said male endelectrically isolating said respective threads.
 25. A sub-assemblyaccording to claim 24 further comprising: a third sub and a fourth sub;a second non-conductive ring interposed between said third and fourthsub; and a second insulative layer interposed between respective threadsof a male end of said third sub and a female end of said fourth sub,said second insulative layer comprising a ceramic coating; wherein saidsecond insulative layer is applied to said male end of said third suband said female end of said fourth sub is then connected to said maleend of said third sub electrically isolating said respective threads ofsaid third and fourth sub, and wherein said second sub is connected tosaid third sub.
 26. A sub-assembly according to claim 24 wherein saidring is made from a ceramic material being one of Technox™ andYTZP-Hipped™.
 27. A sub-assembly according to claim 24 furthercomprising a first insulative washer inserted into said female end ofsaid second sub and being interposed between said first and second subs.28. A sub-assembly according to claim 25 further comprising a secondinsulative washer inserted into said female end of said fourth sub andbeing interposed between said third and fourth subs.
 29. A subassemblyaccording to claim 24 wherein said insulative layer further comprisesone or more sub-layer made from any one of insulative tape, woven fabricand epoxy adhesive.
 30. A sub-assembly according to claim 29 whereinsaid woven fabric is any one of Vectran, Dyncema, an Aramid fiberfabric, a ballistic fabric, a loose weave fabric, and a turtle skinweave fabric.